Methods and apparatus for measuring flow velocity in a wellbore using nmr and applications using same

ABSTRACT

The present invention provides methods and apparatus for determining flow velocity within a formation utilizing nuclear magnetic resonance (NMR) techniques in which the shape of the resonance region is restricted so that sensitivity to radial flow or vertical flow is obtained (or both when more than one NMR tool is used). Flow velocity using these NMR tools is determined using decay amplitude, frequency displacement or stimulated echoes (where the spins are stored along the magnetic field instead of the transverse plane to exploit echo decays and frequency displacements) based on the application of adiabatic pulses. Based on the described NMR measurement of flow velocity, additional wellbore parameters may be obtained such as a direct measurement of permeability, an assessment of drilling damage to the wellbore, formation pressure, invasion rate of the mud filtrate or the migration of fine mud particles during sampling operations.

FIELD OF THE INVENTION

[0001] This invention relates to the field of well logging of earthwellbores and, more particularly, to methods for measuring flow velocityin an earth formation with nuclear magnetic resonance techniques and forusing the measured flow velocity to determine various other importantwell logging parameters.

BACKGROUND OF THE INVENTION

[0002] Well logging provides various parameters that may be used todetermine the “quality” of a formation from a given wellbore. Theseparameters include such factors as: formation pressure, resistivity,porosity, bound fluid volume and hydraulic permeability. Theseparameters, which are used to evaluate the quality of a given formation,may provide, for example, the amount of hydrocarbons present within theformation, as well as an indication as to the difficulty in extractingthose hydrocarbons from the formation. Hydraulic permeability—how easilythe hydrocarbons will flow through the pores of the formation—istherefore, an important factor in determining whether a specific wellsite is commercially viable.

[0003] There are various known techniques for determining hydraulicpermeability, as well as other well logging parameters. For example, itis known how to derive permeability from nuclear magnetic resonance(NMR) measurements. NMR measurements, in general, are accomplished bycausing the magnetic moments of nuclei in a formation to precess aboutan axis. The axis about which the nuclei precess may be established byapplying a strong, polarizing, static magnetic field (B_(O)) to theformation, such as through the use of permanent magnets (i.e.,polarization). This field causes the proton spins to align in adirection parallel to the applied field (this step, which is sometimesreferred to as longitudinal magnetization, results in the nuclei being“polarized”). Polarization does not occur immediately, but instead growsin accordance with a time constant T₁, as described more fully below,and may take as long as several seconds to occur (even up to about eightseconds or longer). After sufficient time, a thermal equilibriumpolarization parallel to B_(O) has been established.

[0004] Next, a series of radio frequency (RF) pulses are produced sothat an oscillating magnetic field B₁ is applied. The first RF pulse(referred to as the 90° pulse) must be strong enough to rotate themagnetization from B_(O) substantially into the transverse plane (i.e.,transverse magnetization). The rotation angle is given by:

α=B ₁ γt _(p)  (1)

[0005] and is adjusted, by methods known to those skilled in the art, tobe 90° (where t_(p) is the pulse length and γ is the gyromagneticratio—a nuclear constant). Additional RF pulses (referred to as 180°pulses where α=180°) are applied to create a series of spin echoes. Theadditional RF pulses typically are applied in accordance with a pulsesquence, such as the error-correcting CPMG (Carr-Purcell-Meiboom-Gill)NMR pulse sequence, to facilitate rapid and accurate data collection.The frequency of the RF pulses is chosen to excite specific nuclearspins in the particular region of the sample that is being investigated.The rotation angles of the RF pulses are adjusted to be 90° and 180° inthe center of this region.

[0006] Two time constants are associated with the relaxation process ofthe longitudinal and transverse magnetization. These time constantscharacterize the rate of return to thermal equilibrium of themagnetization components following the application of each 90° pulse.The spin-lattice relaxation time (T₁) is the time constant for thelongitudinal magnetization component to return to its thermalequilibrium (after the application of the static magnetic field). Thespin-spin relaxation time (T₂) is the time constant for the transversemagnetization to return to its thermal equilibrium value which is zero.Typically, T₂ distributions are measured using a pulse sequence such asthe CMPG pulse sequence described above. In addition, B_(O) is typicallyinhomogeneous and the transverse magnetization decays with the shortertime constant T₂*, where: $\begin{matrix}{\frac{1}{T_{2}^{*}} = {\frac{1}{T_{2}} + \frac{1}{T^{\prime}}}} & (2)\end{matrix}$

[0007] In the absence of motion and diffusion, the decay withcharacteristic time T′ is due to B_(O) inhomogeneities alone. In thiscase, it is completely reversible and can be recovered in successiveechoes. The amplitudes of successive echoes decay with T₂. Uponobtaining the T₂ distributions, other formation characteristics, such aspermeability, may be determined.

[0008] A potential problem with the T₂ distributions may occur if theecho decays faster than predicted, for example, if motion of themeasuring probe occurs during measurements. Under these conditions, theresultant data may be degraded. Thus, for example, displacement of themeasurement device due to fast logging speed, rough wellbore conditionsor vibrations of the drill string during logging-while-drilling (LWD)may prevent accurate measurements from being obtained.

[0009] Moreover, it also is known that T₂ distributions do not alwaysaccurately represent pore size. For example, G. R. Coates et al., “A NewCharacterization of Bulk-Volume Irreducible Using Magnetic Resonance,”SPWLA 38th Annual Logging Symposium, Jun. 15-18, 1997, describes themeasurement of bound fluid volume by relating each relaxation time to aspecific fraction of capillary bound water. This method assumes thateach pore size has an inherent irreducible water saturation (i.e.,regardless of pore size, some water will always be trapped within thepores). In addition, the presence of hydrocarbons in water wet rockschanges the correlation between the T₂ distribution and pore size.

[0010] Hydraulic permeability of the formation is one of the mostimportant characteristics of a hydrocarbon reservoir and one of the mostdifficult quantitative measurements to obtain. Often permeability isderived from T₂ distributions, created from NMR experiments, whichrepresent pore size distributions. Finally, permeability is related tothe T₂ data. This way to determine permeability has several drawbacksand is therefore sometimes inapplicable.

[0011] Typically T₂ distributions are measured using theerror-correcting CPMG pulse sequence. In order to provide meaningfulresults, the length of the recorded echo train must be at least T₂^(max). During this time period, as well as during the precedingprepolarization period, the measurement is sensitive to displacements ofthe measuring device. Further, in some cases, the T₂ distributions donot represent pore size distributions, e.g., hydrocarbons in water wetrocks change the correlation between T₂ distribution and pore sizedistribution. Finally, the correlation between pore size distributionand permeability of the formation is achieved using severalphenomenological formulae that are based on large measured data sets,displaying relatively weak correlation. In carbonates, these formulaebreakdown because of the formations' complex pore shapes.

[0012] A more direct way to measure permeability is by measurements ofinduced flow rates using a packer or probe tool. Still, this measurementrequires extensive modeling of the formation response which includes thegeometry of the reservoir and of the tool, the mud cake, and theinvasion zone. The effort required for modeling however, could besignificantly reduced if flow velocity could be obtained. It would beadvantageous to obtain flow velocity, which could be used to determinevarious parameters required for modeling so that the number of variablesrequired for modeling is reduced.

[0013] For at least the foregoing reasons, it is an object of thepresent invention to provide apparatus and methods for determining flowvelocity utilizing NMR techniques.

[0014] It is a still further object of the present invention to providemethods for determining permeability utilizing NMR measurements of flowvelocity.

[0015] It is an even further object of the present invention to providemethods for determining the extent of drilling damage to the formation,formation pressure, mud filtration rate and changes in the invaded zoneduring sampling utilizing NMR measurements of flow velocity.

SUMMARY OF THE INVENTION

[0016] These and other objects of the invention are accomplished inaccordance with the principles of the invention by providing methods andapparatus for determining flow velocity utilizing nuclear magneticresonance (NMR) techniques and for providing measurements of otherwellbore parameters based on the flow velocity measurements. Thepreferred embodiments include methods and apparatus in which flowvelocity is determined without knowledge of T₂ or the pressuredistribution. The flow velocity measurements are made using NMRtechniques in which the shape of the resonance region is varieddepending on whether radial or vertical sensitivity is desired. In anembodiment that requires knowledge of T₂, the decay of the echoamplitude is measured. If both radial and vertical sensitivity aredesired, multiple NMR devices may be provided in a single wellbore toolwhere each NMR device is designed to measure a specific orientation.

[0017] In other preferred embodiments of the present invention, NMRdetermination of frequency displacement, rather than signal decay, isutilized to determine flow velocity. An advantage of these techniquesalso is that no reference measurements need be taken because thedetection of signal decay is not employed. This can be achieved byanalyzing the echo shape instead of the echo amplitude or by standardNMR one-dimensional frequency selective or two-dimensional methods. Instill other preferred embodiments, an encoding pulse is substituted forthe traditional 90° pulse, and adiabatic pulses are substituted for thetraditional 180° pulses. These techniques are advantageous if the B_(O)gradient is small, e.g., in the case of a B_(O) saddle point, becauseonly an inhomogeneous field B₁ is required, rather than a B_(O)gradient.

[0018] The methods and apparatus of the present invention for obtainingflow velocity using NMR techniques also are applicable to determiningvarious wellbore parameters during wellbore drilling operations. Forexample, by inducing fluid to flow within the formation such as bywithdrawing fluid from the formation into the NMR tool or into thewellbore, the NMR determination of flow velocity may be used inconjunction with a differential pressure measurement to provide adirect, small-scale measurement of permeability due to the fact that theNMR data provides an extremely localized measurement of fluid velocity.Alternatively, the NMR techniques of the present invention may be usedto obtain an assessment of the drilling damage to the formation.

[0019] In addition, the NMR techniques of the present invention may beused to determine formation pressure by establishing conditions in thewellbore (for example, by using a packer module) such that no filtrationof wellbore fluid occurs across the mudcake and simultaneously measuringthe pressure at the interface between the mudcake and the formation.Another important parameter that may be determined using the NMRtechniques of the present invention is mud filtration rate (sometimesreferred to as invasion). This parameter may be particularly importantbecause it provides a direct measure of the quality of the mud systembeing employed and may provide an advance indication of potentialproblems. Also, the NMR techniques of the present invention may be usedto monitor changes in the invaded zone during sampling operations. Undersuch conditions, it is often important to monitor the migration of finemud particles (or “fines”) that may give rise to plugging of theformation where the sampling is being conducted. Moreover, while thedetermination of various operational parameters is described herein,persons skilled in the art will appreciate that various other parametersmay be obtained utilizing the NMR techniques of the present invention.

BRIEF DESCRIPTION OF THE DRAWINGS

[0020]FIG. 1 is a schematic diagram of one embodiment of an NMR loggingapparatus for measuring flow velocity in accordance with the principlesof the present invention;

[0021]FIG. 2a is a plan-view schematic representation of one embodimentof an NMR tool component that may be utilized in conjunction with theNMR logging apparatus of FIG. 1 in accordance with the principles of thepresent invention;

[0022]FIG. 2b is a cross-sectional-view schematic representation of oneembodiment of an NMR tool component that may be utilized in conjunctionwith the NMR logging apparatus of FIG. 1 in accordance with theprinciples of the present invention;

[0023]FIG. 3a is a plan-view schematic representation of anotherembodiment of an NMR tool component that may be utilized in conjunctionwith the NMR logging apparatus of FIG. 1 in accordance with theprinciples of the present invention;

[0024]FIG. 3b is a cross-sectional-view schematic representation ofanother embodiment of an NMR tool component that may be utilized inconjunction with the NMR logging apparatus of FIG. 1 in accordance withthe principles of the present invention;

[0025]FIG. 4 is a side-view schematic representation of one embodimentof a pressure measurement tool component that may be used in conjunctionwith the NMR tool components of FIGS. 2 and 3 in accordance with theprinciples of the present invention;

[0026]FIG. 5 is a schematic diagram of another embodiment of an NMRlogging apparatus in accordance with the principles of the presentinvention;

[0027]FIGS. 6a-e are schematic examples of acquired exchangedistribution and the effects of frequency displacement for a given echoin accordance with the present invention;

[0028]FIG. 7 is a flow chart illustrating steps for determining flowvelocity in accordance with the principles of the present invention; and

[0029]FIG. 8 is a pulse sequence illustrating the use of adiabatic pulseechoes in accordance with the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0030] The methods and apparatus of the present invention utilizeseveral techniques to determine various qualitative parameters regardinga given formation from NMR measurements. The initial techniques providea measurement of formation fluid speed (i.e., flow velocity) that leadsto a determination of formation pressure and/or mud filtration rate. Toaccomplish these techniques, the NMR tool must include the ability toinduce flow in the formation (one tool component) and to create an NMRshell in the formation that is used to measure the induced flow (asecond tool component). When the basic techniques described herein aresupplemented by measurements of local pressure gradient (e.g., by addinga third tool component to the drill string), the techniques of thepresent invention may also provide a determination of permeabilityand/or skin damage (i.e., the area between the wellbore and the virginformation).

[0031] Described herein are various ways to induce fluid to flow withinthe wellbore in conjunction with the determination of flow velocity. Forexample, during drilling, the pressure in the wellbore fluid may bechanged via an external device such as a rig pump. Alternatively, a toolsuch as that shown in FIG. 1 and described below may be deployed(drilling would not be occurring under these circumstances) that pumpsfluid into or withdraws it from the packer interval. Still another wayto induce fluid flow is through the use of a port located on a pad, suchas that shown in FIGS. 3a and 3 b and described below, in which casefluid would again be pumped into or out of the tool.

[0032] Various known techniques exist for determining flow velocity. Forexample, NMR techniques may utilize switched gradients to encode flowand diffusion. However, under certain circumstances switched gradientsmay be difficult, if not impossible, to produce, and in the presence oflarge static gradients, they may be negligible. The echo measurements ofthe present invention can be produced such that they rely only on staticgradient B_(O) or B₁ fields instead of switched gradients, andtherefore, it works for “inside out” NMR conditions where measurementsare made outside the magnet configuration.

[0033]FIG. 1 shows an illustrative example of an NMR logging device 100that measures flow velocity. Logging device 100 includes four modulesincluding: packer 102, NMR tool 104, packer 106 and NMR tool 108. Whilelogging device 100 is shown having four modules, persons skilled in theart will appreciate that various other combinations of logging tools maybe used, including other known logging tools that are not mentionedherein. For example, logging device 100 may be used without NMR tool108, in which case device 100 only would have three modules.

[0034] As shown in FIG. 1, logging device 100 is located in wellbore 110that previously has been drilled in earth formation 112. Logging device100 is suspended in wellbore 110 from logging cable 114. It is withincontemplation of this invention for the logging device 100 to beconveyed in the wellbore by drill pipe or coiled tubing. As described inmore detail below, the principles of the present invention also may beapplied to logging-while-drilling (LWD) operations, in which caselogging device 100 (or the applicable modules (e.g., packers)) thenwould be located within a drill string (not shown) behind the drill bit(not shown). Also shown in FIG. 1 are flow lines 116, and resonancelines 118 and 120 that are explained in more detail below.

[0035] It is known that a net displacement of a resonated substance withrespect to its spatial position in the field maps of the measuringdevice at the moment of excitation by a pulse sequence leads to adecreased decay amplitude (DA) in the measured signal amplitude A. Thisdisplacement may be a product of actual displacement, translationaldiffusion or a combination of both. Normal NMR multi-echo experimentscorrect to a high degree for diffusion, so that given sufficiently shortecho spacing only the total displacement due to diffusion at detectiontime is important. Directed flow, however, can be detected even in thepresence of diffusion as long as the displacement due to flow is atleast comparable to the displacement due to diffusion.

[0036] The loss of the I-th echo can be characterized by a loss factor:λ_(i)=A_(i)/A⁰ _(i), where A⁰ _(i) is the amplitude of the I-th echounder the same circumstances except for no displacement. Importantly,the loss factor is independent of the relaxation time distribution ofthe substance being investigated, if the displacement is caused by auniform motion with a constant scalar velocity v, the loss factor vectoris a function of v only (i.e., a single variable). Therefore, velocity vmay be determined from the loss factor vector λ^ (vectors herein aredenoted with the character “^ ”). This requires that severalmeasurements be made with varying velocities. Let the measured responsevector be S_(v^ =){A₁, . . . , A_(n)} and assume a measured response,such as for v=0, produces a response vector S₀^ ={A⁰ ₁, . . . , A⁰_(n)}, then the characteristic loss factor vector is directly given byλ^ ={A₁/A⁰ ₁, . . . , A_(n)/A⁰ _(n)}. Thus, for a given measurementapparatus with known field maps and a fixed pulse sequence, a lookuptable of λ^ (V) can be calculated from which v can be derived.

[0037] The methods and apparatus of the present invention utilize anexcitation pulse in accordance with field maps B_(O) and B₁ that causethe resonance region where spins are excited by the pulse to have aspecific shape. The specific shapes are selected depending on thegeneral direction of fluid flow that is being measured. For example, ifradial flow is an important component of a desired measurement, the NMRtool used in flow velocity measurement is configured such that a thin,long, cylindrically-shaped resonance region is defined. Acylindrically-shaped resonance region is essentially unaffected byvertical displacements (such as, for example, vertical movement oflogging drill string 114), while being especially sensitive to radialmovement. It can be created, for example, using an axisymmetric gradientdesign for B₀ like that employed in the MRIL® tool of the NumarCorporation.

[0038] On the other hand, if vertical displacement is an importantfactor, the NMR tool may be configured to provide a resonance regionthat is essentially a flattened torus-shape (like a flattened doughnut).A flattened torus-shaped resonance region, which is especially sensitiveto vertical displacement, may be created, for example, by using aJasper-Jackson saddle point design and tuning the operating frequenciesabove the Larmor frequency at the saddle point (see U.S. Pat. No.4,350,955). When both radial and vertical displacement are importantparameters, two separate NMR tools, such as tools 104 and 108 of FIG. 1,may be utilized. Under such circumstances, NMR tool 104 may beconfigured to form a cylindrically-shaped resonance region, while NMRtool 108 may be configured to form a flattened torus-shaped resonanceregion. Additionally, if a gradient B₁ field is present, it is alsopossible to utilize a saddle-point-shaped B_(O) at resonance.

[0039] In addition to determining flow velocity v from the loss factorλ_(i), it is also possible to determine flow velocity by analyzing theecho shape in either the frequency or time domain. Or, the fact thatflow causes the phases of the echoes to shift in the x-y plane (of theconventional NMR “rotating” coordinate system) can be utilized tocharacterize the motion and further enhance resolution. The correctionvector λ^ (v), thus can be determined solely by quantitative analysis ofthe recorded echo phases and echo shapes in the time domain or frequencydomain and knowledge of the T₂ distribution is not required. In the caseof a monotonic gradient G, it is possible to obtain information aboutthe flow direction by qualitative analysis of the echo shape.

[0040] As described above, FIG. 1 shows one embodiment of an NMR loggingdevice 100 that includes two NMR tools 104 and 108, each beingconfigured to measure a different aspect of flow velocity. As NMR tool104 is configured to measure radial displacement, its resonance regionis illustrated by resonance lines 118, while resonance lines 120illustrate the vertically oriented resonance region of NMR tool 108(note that flow lines 116 pass through resonance lines 118 and 120). Inaddition, packers may be used to create a specific flow path. Forexample, FIG. 1 shows NMR tool 104 between packers 102 and 106 in anisolated portion of wellbore 110. Packers 102 and 106 utilize expansioncomponents 122 and 124, respectively, to effectively seal off a portionof the wellbore. Then, NMR tool 104 induces fluid flow by drawing fluidfrom the wellbore into the tool itself through a fluid inlet port. Thiscreates a local pressure change in the isolated area which induces aflow of fluid in the formation (shown in FIG. 1 by flow lines 116).

[0041]FIGS. 2a, 2 b, 3 a, and 3 b show embodiments of NMR toolcomponents that may be used in accordance with the principles of thepresent invention to measure flow velocity, either in conjunction withthe NMR tools of FIG. 1, or other NMR tool configurations. The NMR toolcomponents of FIGS. 2a, 2 b, 3 a, and 3 b, as well as the NMR toolcomponents shown in FIG. 4 also include the capability to providepressure measurements when pressed against the wall of the wellbore(contrary to the device shown in FIG. 1 that is held away from thewellbore wall by packer modules). Moreover, while the fields of thedevice shown in FIG. 1 are axially symmetric, the fields of the NMR toolcomponents of FIGS. FIGS. 2a, 2 b, 3 a, 3 b, and 4 are not.

[0042]FIGS. 2a and 2 b show one embodiment of an NMR tool pad 200 thatcould be used on NMR tool 108, NMR tool 504 (describe below) or in otherNMR tool configurations not shown. Pad 200 includes back-up plate 202,sealing element 204, and pressure monitor probes 206. Additionally,resonance region 208, which is similar to resonance lines 120 of FIG. 1(but, contrary to resonance lines 120, are not axially symmetric),illustrates the sensitivity to motion along an imaginary line joiningthe pressure probes 206 (of FIG. 2a). If used with logging device 100,pad 200 would actually be rotated 90° so that resonance region 208conforms with resonance lines 120. Moreover, in order to utilizepressure monitor probes 206, pad 200 must be configured such that it isplaced against the wellbore wall (see, for example, the NMR toolconfiguration shown in FIG. 5 and the corresponding text below) andhydraulic communication is made between probes 206 and the formation.

[0043]FIGS. 3a and 3 b show another embodiment of an NMR tool pad 300that could be used on NMR tool 108, NMR tools 400 and 500 (describedbelow) or on a single NMR tool (not shown) that is configured to producetwo different resonance regions (i.e., vertical and horizontal). Pad 300includes back-up plate 302, sealing element 304, pressure monitor probes306 that measure pressure azimuthal gradients 316, pressure monitorprobes 312 that measure elevational gradients 322 and fluid inlet port314 that draws fluid into the logging device. Additionally, resonanceregion 308 illustrates the sensitivity to radial motion, while resonanceregion 318 illustrates the sensitivity to vertical motion. It should benoted that, because a pressure sensor is not placed into the formation,the radial component of the pressure drop is not measured. Assuming thatthe formation is isotropic in the horizontal plane, then the radialpermeability component is substantially similar to the azimuthalcomponent. Thus, obtaining an azimuthal measurement via probes 306provides a radial answer.

[0044] It should be noted that, in accordance with the principles of thepresent invention, the shaped resonance regions are not limited simplyto cylinders and flattened-toroids, and that the tools described aboveare merely illustrative of how the present invention may be applied tosuch devices. For example, the pads of FIGS. 2a and 3 a are generallysensitive to motion in the circumferential direction, i.e., rotation ofthe drill string within the borehole. Thus, the present invention may beutilized to produce specific-shaped resonance regions that aresubstantially smaller in one direction than any other direction, andthat the smaller direction is beneficial because it providesmeasurements that essentially are unaffected by movement in thatdirection. For example, the thin, long, cylindrically-shaped region isgenerally unaffected by vertical movement.

[0045]FIG. 4 shows another embodiment of a logging device 400 that maybe used in accordance with the principles of the present invention.Rather than utilize a single pad 300 to perform a wide variety offunctions (which accordingly increases the complexity and expense ofproducing such a pad), device 400 offers an alternative when used inconjunction with, for example, pad 200 of FIG. 2a. Device 400 includespressure monitor probes 402, 404 and 406, another NMR tool (not shown)and a fluid sampling probe 408 that is used to sample formation fluidinstead of fluid inlet port 314 of pad 300 (see FIG. 3a).

[0046] Device 400 has multiple applications. First, NMR probes 402, 404and 406 may be utilized to obtain a small-scale permeability measurement(in both vertical and horizontal directions) of the invaded zone, i.e.,the zone of the formation affected by drilling damage. Second, probes406 and 408 may be used to perform a “deeper” permeability measurementby conducting a pressure interference test between the probes (providedthe spacing between probes 406 and 408 is sufficiently large). Probe 408would be used to create a pressure pulse by withdrawing fluid into theprobe. A comparison of the two different permeability measurements(i.e., the small-scale or invaded zone measurement, and the “deeper” orvirgin reservoir) provides information on the formation heterogeneity.In addition, if the extent of the damaged zone is available, forexample, from an array resistivity log, then a value of the “skin” alsomay be determined.

[0047] Persons skilled in the art will appreciate that, although threespecific configurations of logging tools have been described, that thereare countless other combinations that may be used to practice theprinciples of the present invention. For example, a fifth probe could beplaced opposite probe 402 on device 400. In such a configuration, probes404, 406 and 408 may be of the type shown in FIG. 3a, while probes 402and the fifth probe may be of the type shown in FIG. 2a. Device 400 alsowould have the capability to determine permeability using the pressureinterference test while determining small-scale permeability using theNMR techniques described herein.

[0048]FIG. 5 shows a schematic illustration of another embodiment of thepresent invention in which an NMR logging device 500 measures localpressure gradients so that parameters such as permeability and skindamage may be determined. Logging device 500 includes an NMR tool 504and packers 506 and 508. Packers 506 and 508 operate as described aboveto create a specific flow path within the earth formation. NMR tool 504includes pressure sensor 530 and NMR tool pads 534 and 536, each ofwhich may be similar to the NMR tool pads described above. For example,NMR tool pad 534 may be used to form resonance region 518 in theformation surrounding wellbore 510. More importantly, NMR tool 504 alsoincludes moveable springs 532 that press pressure sensor 530 againstwellbore wall 511 so that local pressure gradient measurements may beobtained.

[0049] To determine the skin damage, probes 534 and 536 determine thesmall-scale permeability (i.e., local permeability of the damaged zone).Fluid then is flowed into the region between packer modules 506 and 508,which breaks the mudcake seal, to induce a large pressure pulse. Thepressure pulse is used to perform an interference test between thepacker probe and another probe (not shown) located outside the packerregion. Persons skilled in the art will appreciate that the small-scaleNMR permeability measurement must be made prior to breaking the mudcakeseal and the interference test when utilizing device 500. Moreover, withthe addition of a pressure gauge (not shown) located between packermodules 506 and 508, device 500 also may be utilized for thedetermination of skin and formation pressure.

[0050] When formation pressure is being determined, packer modules 506and 508 are utilized to isolate a portion of the wellbore. NMR probe 504is utilized to produce resonance shell 518 that is used to sense whenthere is no mud filtrate invasion into the formation—that filtrate fluidspeed is zero. Pressure monitor probe 530 senses the pressure on theother side of the mudcake from the wellbore, while another pressuresensor (not shown) located between the packers monitors the pressure inthe packer interval. Fluid is then withdrawn or injected until a zerofluid speed condition exists, at which point the pressure in the packerinterval should be the same as the formation pressure.

[0051] The methods of quantitative interpretation are simplified when auniform gradient field is present because in a uniform gradient G^ , therelationship between a displacement vector rA(t) and a change inresonance frequency δω also is a function of one parameter: G^ ·r^ =δω.Therefore, every change in resonance frequency corresponds to aparticular displacement and δω_(i) at the time I*t_(e) of echo I can berelated to an average velocity r/(I*t_(e)). Every echo I of a given echotrain thus represents an experiment with a different “mixing” time(I*t_(e)) in the sense of the standard NMR exchange experiments.However, the signal-to-noise ratio can be enhanced by using all of theechoes together to extract velocity.

[0052] For example, an analysis of the echo shape f(t) (or echo spectrumf(ω)) only provides information regarding where the sum of the spinsmoved, but does so in a fast and efficient manner so that few NMRexperiments are needed. If more information is required, such as adetermination of where each spin is moving, frequency selectiveexperiments (either one-dimensional or two-dimensional) may beperformed, but such experiments are more demanding in terms ofmeasurement time and the number of measurements required. As a variationfrom the previously described NMR techniques, this embodiment of thepresent invention requires that the spins be marked or labeled independence of their resonance frequency by applying RF pulses eitherimmediately before or after the excitation pulse. The simplest way ofmarking would be a saturation sequence that creates a resonancefrequency dependent saturation pattern. A measurement of velocity maythen be obtained by correlating resonance frequency at two differenttimes.

[0053]FIGS. 6a-6 e show various schematic examples of two-dimensionalexchange spectra of the I-th echo. FIG. 6a shows a two-dimensionaldistribution 602 for the I-th echo in the absence of displacement andtranslational diffusion. FIG. 6b shows a two-dimensional distribution604 for the I-th echo that indicates the influence of strong diffusion(or statistical displacement). FIG. 6c shows a two-dimensionaldistribution 606 that is the result of displacement occurring in thelower field with a given velocity v. FIG. 6d shows a similartwo-dimensional distribution 608 that results from motion having thesame velocity, but opposite direction (i.e., into the high field).Finally, FIG. 6e shows the result of doubling the velocity shown in FIG.6d (the result would be the same whether velocity (v), “mixing” time(I*t_(e)) or echo number (2*I) were doubled). FIGS. 6a-6 e show that, inthis embodiment, only frequency displacement affects the determinationof flow velocity (versus decay amplitude as described above). Personsskilled in the art will appreciate that the data shown in FIGS. 6a-6 e,without encoding (i.e., just measuring echo shape) would appear ascurved projections instead of spectra, as shown by way of illustrationin FIG. 6e by dashed line curves 612 and 614. Similar projections alsocould be produced for each of FIGS. 6a-6 d, if desired.

[0054]FIG. 7 shows a flow diagram that illustrates the methods of thepresent invention for determining flow velocity. In a step 702, the toolis placed in the wellbore (depending on exactly which tool and thedesired parameters, step 702 may be performed as part of drillingoperations or it may be performed separate from drilling operations, forexample, when local gradient pressure measurements are necessary). Fluidis induced to flow in a step 704 in any known manner. For example, viaexternal pumping using equipment from the top of the borehole or byutilizing pumping ports on the well logging tool itself, as shown inFIG. 3a (i.e., fluid inlet port 314).

[0055] A strong, polarizing, static magnetic field is applied to theformation in a step 706, through the use of, for example, permanentmagnets, that polarizes a portion of the formation (i.e., longitudinalmagnetization). An oscillating magnetic field then is applied in a step708 in accordance with field maps B_(O) and B₁ to produce a resonanceregion having a specific shape dictated by the desired motionsensitivity. The oscillating magnetic field is the result of theapplication of a series of RF pulses to the formation which forms aresonance region. The specific shape of the resonance region, which isdetermined by the specific sequence of RF signals, is chosen dependingon the desired axis of sensitivity. For example, a thin, long,cylindrically-shaped resonance region may be produced for measurementsthat require minimal impact by vertical displacement of the drillstring.

[0056] The sequence of applied RF pulses excites specific nuclear spinsin the formation that induce a series of spin echoes. The spin echoesinduced by the oscillating magnetic field are measured in a step 710.The decay loss factor is determined in a step 712 (e.g., if there is nomovement, the decay loss factor will be unity). Finally, the flowvelocity is derived, in a step 714, from the decay loss factor. Personsskilled in the art will appreciate that other parameters, such aspermeability, require additional steps not shown in FIG. 7 (for example,in order to determine permeability, a step of measuring local pressuregradients must be added).

[0057] One advantage of the change in resonance frequency measurement offlow velocity is that, for identical conditions, the resonance frequencymeasurement provides detection of much smaller displacement velocitiescompared to the decay amplitude embodiment previously described.However, the frequency selective analyses (both one-dimensional andtwo-dimensional) require the presence of a uniform gradient field thatis not a requirement of the echo shape and decay analysis. Thus, undercircumstances where a uniform gradient exists and very thick resonanceregions are required, resonance frequency measurements may beparticularly advantageous. Moreover, the spread in displacement could beanalyzed in terms of free fluid, bound fluid, viscosity or theinteraction of the fluid with the rock surface to provide additionalinformation about the formation and the fluids present therein.

[0058] Many of the previously described NMR measurements of flowvelocity rely on a relatively high gradient in B_(O). Therefore, thosemeasurement techniques are not useful under circumstances wheresaddle-point measurements need to be made. A saddle-point tool can beused to measure flow velocity, however, a gradient in the pulseamplitude B₁ is present. There are various known techniques for applyingmagnetic field gradients to produce stimulated echoes, however, thosetechniques all require an inhomogeneous B₁ encoding pulse followed bythe application of a homogeneous B₁ refocusing pulse and homogeneous B₁reading pulses. Inside out NMR saddle-point tools naturally produce therequired strongly inhomogeneous B₁ field (from the RF coil), but thesubstantially homogeneous B₁ field simply is not achievable.

[0059] The refocusing/reading pulse may, in accordance with the presentinvention, be accomplished with the inhomogeneous B₁ field by utilizingadiabatic methods as shown in FIG. 8. For example, following encodingpulse 802 (that spirals the spins between the longitudinal and atransverse direction), a series of adiabatic refocusing pulses (AFP) 804are applied to create an echo train. The echo train is then spooled backby applying a negative encoding pulse 806 to decode the echo train.Then, excitation may be performed adiabatically by applying an adiabaticfast half passage pulse (AHP) 808 into the resonance zone just prior tothe application of detection sequence 810.

[0060] Detection sequence 810 may be accomplished by applying anadiabatic fast half passage pulse into the resonance zone—starting at afrequency outside of the resonance zone, varying the frequency of therefocusing pulse so that it sweeps through the entire resonance zone,and stopping at the resonance frequency. Alternately, the B_(O) fieldmay be varied instead of the frequency. In addition, if diffusion ispresent, its effects may be suppressed by applying a multi-echo sequencewith many refocusing pulses, such as refocusing pulse sequence 804, tointroduce phase errors that cancel themselves out when an even number ofrefocusing pulses are applied. For the detection sequence, a single echoor a multi-echo train may be utilized. Effective excitation may beprovided by an adiabatic pulse by applying an adiabatic half passagepulse to turn the spins into the transverse plane.

[0061] The capability to measure flow velocity provides additionaladvantages. For example, NMR apparatus may be installed within a drillstring and operated during a pause in drilling operations to provideimmediate feedback. One particularly useful parameter that may bedetermined is a direct measurement of permeability based on Darcy'sformula which states: $\begin{matrix}{v = {\frac{1}{\mu}K*{grad}*p}} & (3)\end{matrix}$

[0062] where v represents seepage velocity, μ represents fluidviscosity, K represents the permeability (tensor) and p is the localvalue of the fluid pressure. In earth formations at the scale of themeasurements addressed herein, the permeability K is essentiallydetermined by two independent values K_(h) and K_(v) (i.e., thehorizontal component and the vertical component, respectively).

[0063] By applying the NMR measurements described above to determinelocal fluid velocity, values for K_(h) and K_(v) may be directlyobtained (provided that probes are set to measure local pressuregradients, such as the configurations shown in FIGS. 4 and 5). Forexample, K_(v)=μv_(z)/dp/dz. Assuming the fluid viscosity μ is known,dp/dz easily may be obtained through the use of pressure monitor probes,and because v_(z) is determined based on one of the above-described NMRmeasurements, K_(v) can be determined. If it is assumed that thepermeability is isotropic in the transverse plane, then an azimuthalmeasurement of the pressure gradient utilizing pressure monitor probesand a measurement of fluid velocity (as described above) provides K_(h)(based on the derivation that K_(h)=μv_(θ)r_(w)/dp/dθ). Once K_(h) andK_(v) are determined, permeability K is also determined, in this case insitu. However, it should be noted that, as described above, becauselocal pressure gradient measurements can not be obtained during drillingoperations (because the sensor probes must be placed against thewellbore wall), neither can permeability measurements be made duringdrilling operations.

[0064] Another parameter that may be determined using the flow velocitymeasurements of the present invention is an assessment of drillingdamage (i.e., the alteration of permeability into the formation a radialdistance r_(d) due to drilling operations). This assessment may bedetermined by determining the additional pressure drop or “skin” Sassociated with the altered region of the formation when fluid flowsinto the wellbore (as this assessment also relies on a measurement oflocal pressure gradient, it also cannot be performed during drillingoperations). The determination of S is based, at least in part on thepermeabilities of the virgin formation and the damaged formation. Thus,skin S may be calculated as follows: $\begin{matrix}{S = {\left( {\frac{K_{\infty}}{K_{d}} - 1} \right){\ln \left( \frac{r_{d}}{r_{w}} \right)}}} & (4)\end{matrix}$

[0065] where r_(w) is the wellbore radius, and K_(∞) and K_(d) are thepermeabilities of the virgin formation and damaged zones, respectively.Accordingly, once r_(d) is determined from for example, arrayresistivity logs, a detailed, depth-resolved model of the damaged zonecan be constructed and a value of the skin may be determined.

[0066] It is also possible to take measurements of formation pressure,however, such measurements, as explained above, also cannot be takenwhile drilling is active. Formation pressure may be measured by applyingthe velocity measurement principles described above, and detecting thecondition when the formation fluid is at rest (i.e., motionless). Thismay be accomplished by manipulating the wellbore pressure whilemonitoring the measured velocity. When the measured velocity is zero,the local pressure at the test depth must be equal to that of theformation (such that no fluid flows either from the wellbore into theformation (i.e., invasion), or vice versa). At that instant, the mudpressure, which can be determined using conventional tools, is anaccurate measure of the formation pressure.

[0067] It should be recognized that it may be difficult to determine thezero velocity condition, because resolution decreases at low velocities.In that case, formation velocity could be measured while adjustingwellbore pressure in discrete steps. A plot of the measured velocity asa function of local wellbore pressure may be extrapolated to determinethe pressure at which zero velocity would occur. While nonlinearities inthe mudcake transmissivity may be manifested in the pressure-velocityrelationship, such steps may be necessary where it is prohibitive toreduce the well pressure well below formation pressure.

[0068] When, for reasons of well control, safety or precision inmeasurement, it is desirable to adjust the pressure in the entirewellbore, the local formation pressure may be determined by theapplication of principles shown in FIG. 5, as described above. An NMRexperiment to measure formation pressure could be conducted using athree module logging device where a radially sensitive NMR tool islocated between two packer modules (as shown by modules 504, 506 and508). The packer modules 506 and 508 could isolate a portion of thewellbore 510 and NMR module 504 could include a pumpout unit that wouldinject and/or extract fluid into/from the isolated interval in order toadjust the pressure in the isolated portion of the wellbore. Aconventional pressure probe 530 also could be utilized within the packerinterval that directly measures the pressure of the sandface interface(i.e., the interface between the mudcake and the formation) in order toaccurately determine the transmissivity of the mudcake. Such techniquesmay not be suitable for low permeability formations where steadypressure conditions may not be achievable in the time period allocatedfor testing.

[0069] The development of the mudcake itself is another importantparameter that may be determined in accordance with the NMR measurementsof velocity described above. It is important to be able to determine therate of loss of mud filtrate into the formation (i.e., invasion), whichis an accurate indicator of the overall quality of the mud system beingemployed. Mud filtration rate may be determined by integrating fluidflow measurements over a cylindrical surface concentric with thewellbore. The result is a direct measurement of the volumetric flux ofthe invading fluid provided that near steady-state conditions arepresent (for example, the rate at which mud filtrate invades theformation should be substantially constant). Thus, this parameter alsocannot be determined while drilling is occurring.

We claim:
 1. A method of determining flow velocity of a fluid in anearth formation utilizing at least one nuclear magnetic resonance (NMR)tool that is placed in a wellbore in the formation and which produces astatic magnetic field and measures induced magnetic signals, the methodcomprising: inducing the fluid to flow; applying the static magneticfield from the NMR tool to a volume of the formation, the staticmagnetic field polarizing a substantial portion of the formation that issubject to the static magnetic field; applying an oscillating magneticfield to a specific part of the polarized portion to induce theproduction of measurable signals, the oscillating magnetic field beingapplied in accordance with field maps B_(O) and B₁ so that a resonanceregion having a specific shape corresponding to a desired sensitivity isformed in the formation; measuring the induced signals; determining adecay loss factor from the measured induced signals; and deriving theflow velocity based on the determined decay loss factor.
 2. The methodof claim 1, wherein the desired sensitivity corresponds to radial flowand the shape is a thin, long cylindrical shell.
 3. The method of claim1, wherein the desired sensitivity corresponds to vertical flow and theresonance region is flattened torus-shaped region.
 4. The method ofclaim 1, wherein the resonance region having a specific shape issensitive to circumferential motion.
 5. The method of claim 1, whereinthe measurement of the induced signals comprises: measuring amplitude ofthe induced signals.
 6. The method of claim 1, wherein the inducedsignals are produced from spin echoes, each having an echo shape andphase, and the decay loss factor is determined by quantitativelyanalyzing the echo shapes and echo phases in time domain.
 7. The methodof claim 1, wherein the induced signals are produced from spin echoes,each having an echo shape and phase, and the decay loss factor isdetermined by quantitatively analyzing the echo shapes and echo phasesin frequency domain.
 8. The method of claim 1, wherein the inducedsignals are produced from spin echoes, each having an echo shape andphase, the method further comprising: determining flow direction byquantitatively analyzing the echo shapes in frequency domain.
 9. Themethod of claim 1, wherein the induced signals are produced from spinechoes, each having an echo shape and phase, the method furthercomprising: determining flow direction by quantitatively analyzing theecho shapes in time domain.
 10. The method of claim 1, wherein theresonance region is saddle-point-shaped.
 11. The method of claim 1,wherein the desired sensitivity includes radial flow and vertical flow,and applying the oscillating magnetic field comprises: applying via afirst NMR tool a first oscillating magnetic field, the first oscillatingmagnetic field being applied in accordance with specific field mapsB_(O) and B₁ so that a resonance region having a thin, long cylindricalshell shape is formed in a first specific part of the polarized portionto induce the production of measurable signals that are sensitive toradial flow; and applying via a second NMR tool a second oscillatingmagnetic field, the second oscillating magnetic field being applied inaccordance with specific field maps B_(O) and B₁ so that a resonanceregion having a flattened torus shape is formed in a second specificpart of the polarized portion to induce the production of measurablesignals that are sensitive to vertical flow.
 12. The method of claim 11,wherein the first and second NMR tools are included within a drillstring and NMR measurements of flow velocity are made while drilling ofthe wellbore occurs.
 13. The method of claim 11, further comprising:taking a local pressure gradient measurement; deriving a horizontalcomponent of flow velocity from the measurable signals induced by thefirst NMR tool; deriving a vertical component of flow velocity from themeasurable signals induced by the second NMR tool; and deriving ameasurement of permeability from the horizontal component, the verticalcomponent and the local pressure gradient measurement.
 14. The method ofclaim 1, wherein the NMR tool is included within a drill string and NMRmeasurements of flow velocity are made while drilling of the wellboreoccurs.
 15. The method of claim 1, further comprising distinguishingdiffusion from induced fluid flow.
 16. The method of claim 1, whereinapplying an oscillating magnetic field comprises: applying a sequence ofrefocusing pulses that induce spin echoes to be produced, the spinechoes corresponding to the measurable signals.
 17. The method of claim16, wherein the sequence of refocusing pulses is applied in accordancewith a CPMG pulse sequence.
 18. A method of determining flow velocity ofa fluid in an earth formation utilizing at least one nuclear magneticresonance (NMR) tool that is placed in a wellbore in the formation andwhich produces a static magnetic field having a uniform gradient andmeasures induced magnetic signals, the method comprising: inducing thefluid to flow; applying the static magnetic field having a uniformgradient from the NMR tool to a volume of the formation, the staticmagnetic field polarizing a substantial portion of the formation that issubject to the static magnetic field; applying an oscillating magneticfield to a specific part of the polarized portion of the formation toinduce the production of measurable signals, the oscillating magneticfield being applied in accordance with field maps B_(O) and B₁ so that aresonance region having a shape that corresponds to a desiredsensitivity is formed in the formation; measuring resonance frequency ofthe induced signals; and correlating changes in resonance frequency atdifferent times to a displacement to determine flow velocity.
 19. Themethod of claim 18, wherein the desired sensitivity corresponds toradial flow and the shape is a thin, long cylindrical shell.
 20. Themethod of claim 18, wherein the desired sensitivity corresponds tovertical flow and the resonance region is a flattened torus-shapedregion.
 21. The method of claim 18, wherein the resonance region havinga shape is sensitive to circumferential motion.
 22. The method of claim18, wherein the induced signals are produced from spin echoes and thecorrelation of changes in resonance frequency comprises: gathering anexchange distribution for a given spin echo; and evaluating the exchangedistribution to determine whether displacement has occurred.
 23. Themethod of claim 22, further comprising: evaluating the exchangedistribution, if displacement has occurred, to determine a direction ofthe displacement.
 24. The method of claim 23, further comprising:evaluating the exchange distribution, if displacement has occurred, todetermine relative magnitude of the displacement.
 25. The method ofclaim 22, further comprising: calculating a relaxation time T₂ for eachfrequency component of the exchange distribution; and establishing arelationship between relaxation time T₂ and flow velocity for eachfrequency in the exchange distribution.
 26. The method of claim 18,wherein the desired sensitivity includes radial flow and vertical flow,and applying the oscillating magnetic field comprises: applying via afirst NMR tool a first oscillating magnetic field, the first oscillatingmagnetic field being applied in accordance with specific field mapsB_(O) and B₁ so that a resonance region having a having a thin, longcylindrical shell shape is formed in the formation to induce theproduction of measurable signals that are sensitive to radial flow; andapplying via a second NMR tool a second oscillating magnetic field, thesecond oscillating magnetic field being applied in accordance withspecific field maps B_(O) and B₁ so that a resonance region having ahaving a flattened torus shape is formed in the formation to induce theproduction of measurable signals that are sensitive to vertical flow.27. The method of claim 26, wherein the first and second NMR tools areincluded within a drill string and NMR measurements of flow velocity aremade while drilling of the wellbore occurs.
 28. The method of claim 26,further comprising: taking a local pressure gradient measurement;deriving a horizontal component of flow velocity from the measurablesignals induced by the first NMR tool; deriving a vertical component offlow velocity from the measurable signals induced by the second NMRtool; and deriving a measurement of permeability from the horizontalcomponent, the vertical component and the local pressure gradientmeasurement.
 29. The method of claim 18, wherein the NMR tool isincluded within a drill string and NMR measurements of flow velocity aremade while drilling of the wellbore occurs.
 30. The method of claim 18,further comprising distinguishing diffusion from induced fluid flow. 31.The method of claim 18, wherein applying an oscillating magnetic fieldcomprises: applying a sequence of refocusing pulses that induce spinechoes to be produced, the spin echoes corresponding to the measurablesignals.
 32. The method of claim 31, wherein the sequence of refocusingpulses is applied in accordance with a CPMG pulse sequence.
 33. Themethod of claim 32 further comprising: performing an echoeshape analysison the measured signals.
 34. The method of claim 18, wherein applying anoscillating field comprises: applying a sequence of RF pulses to markspin echoes.
 35. The method of claim 34, wherein correlating changes inresonance frequency comprises: performing frequency selectiveexperiments on the measured induced signals by correlating resonancefrequency of the induced signals at different times.
 36. A method ofdetermining flow velocity of a fluid in an earth formation utilizing atleast one nuclear magnetic resonance (NMR) tool that is placed in awellbore in the formation and which produces a static magnetic field andmeasures induced magnetic signals, the method comprising: inducing thefluid to flow; applying the static magnetic field from the NMR tool to avolume of the formation, the static magnetic field polarizing asubstantial portion of the formation that is subject to the staticmagnetic field; applying an inhomogeneous oscillating magnetic field toa specific region of the polarized portion via an encoding pulse to markspins in the specific region; reapplying the inhomogeneous oscillatingmagnetic field to the specific region via an even number of refocusingpulses that induce the production of measurable signals in the specificregion; measuring amplitude of the induced signals; and deriving theflow velocity based on the measured amplitude.
 37. The method of claim36, wherein the inhomogeneous oscillating magnetic field is applied inaccordance with field maps B_(O) and B₁ to produce a long cylindricallyshell-shaped resonance region in the formation and the determination offlow velocity is sensitive to radial flow.
 38. The method of claim 36,wherein the inhomogeneous oscillating magnetic field is applied inaccordance with field maps B_(O) and B₁ to produce a flattenedtorus-shaped resonance region in the formation and the determination offlow velocity is sensitive to vertical flow.
 39. The method of claim 36,wherein the inhomogeneous oscillating magnetic field is applied inaccordance with field maps B_(O) and B₁ to produce a shaped resonanceregion in the formation and the determination of flow velocity issensitive to circumferential flow.
 40. The method of claim 36, whereinthe inhomogeneous oscillating magnetic field is applied in accordancewith field maps B_(O) and B₁ to produce a saddle-point-shaped resonanceregion in the formation.
 41. The method of claim 36, wherein applyingthe inhomogeneous oscillating magnetic field comprises: applying, via afirst NMR tool, a first encoding pulse in accordance with specific fieldmaps B_(O) and B₁ to produce a resonance region having a longcylindrical shell-shape to establish rotation in spins located in afirst part of the specific region and to induce the production ofmeasurable signals that are sensitive to radial flow; and applying, viaa second NMR tool, a second encoding pulse in accordance with specificfield maps B_(O) and B₁ to produce a resonance region having a flattenedtorus-shape to establish rotation in spins located in a second part ofthe specific region and to induce the production of measurable signalsthat are sensitive to vertical flow.
 42. The method of claim 41, whereinreapplying the inhomogeneous oscillating magnetic field comprises:reapplying, via a first NMR tool, at least a first even number ofrefocusing pulses having the same inhomogeneous oscillating magneticfield as the first adiabatic encoding pulse to the first part of thespecific region; and reapplying, via a second NMR tool, at least asecond even number of refocusing pulses having the same inhomogeneousoscillating magnetic field as the second adiabatic encoding pulse to thesecond part of the specific region.
 43. The method of claim 42, whereinthe first and second NMR tools are included within a drill string andNMR measurements of flow velocity are made while drilling of thewellbore occurs.
 44. The method of claim 42, further comprising: takinga local pressure gradient measurement; deriving a horizontal componentof flow velocity from the measurable signals induced by the first NMRtool; deriving a vertical component of flow velocity from the measurablesignals induced by the second NMR tool; and deriving a measurement ofpermeability from the horizontal component, the vertical component andthe local pressure gradient measurement.
 45. The method of claim 36,wherein the NMR tool is included within a drill string and NMRmeasurements of flow velocity are made while drilling of the wellboreoccurs.
 46. The method of claim 36, wherein the induced signals areechoes and measuring amplitude of the induced signals comprises:detecting a single echo.
 47. The method of claim 36, wherein the inducedsignals are echoes and measuring amplitude of the induced signalscomprises: detecting a multi-echo train.
 48. The method of claim 36,wherein the specific region has a resonance region and reapplying theinhomogeneous oscillating magnetic field comprises: applying anadiabatic fast full passage pulse through the resonance region byvarying the frequency of the refocusing pulses so that the pulses areapplied prior to one end of the region, through the region, and up toresonance frequency.
 49. The method of claim 36, wherein the specificregion has a resonance region and applying the inhomogeneous oscillatingmagnetic field comprises: applying an adiabatic fast half passage pulseinto the resonance region by varying the frequency of the adiabaticpulses so that the pulses are applied prior to one end of the region andinto the region.
 50. The method of claim 36, wherein the even number ofrefocusing pulses comprise a plurality of refocusing pulses thatsuppress decay due to translational diffusion so that amplitudemeasurements are dependent mainly on velocity only when diffusion ispresent.
 51. The method of claim 36, further comprising distinguishingdiffusion from induced fluid flow.
 52. A method of measuringpermeability of an earth formation, the measurement utilizing aplurality of nuclear magnetic resonance (NMR) tools that are includedwithin a drill string, the method comprising: inducing fluid to flow;applying a first static magnetic field from a first NMR tool to a firstvolume of the formation, the first static magnetic field polarizing afirst substantial portion of the formation that is subject to the firststatic magnetic field; applying a first oscillating magnetic field to aspecific part of the first polarized portion to induce the production ofmeasurable signals, the first oscillating magnetic field being appliedin accordance with specific field maps B_(O) and B₁ to produce a firstresonance region having a thin, long cylindrical shell-shape in thefirst volume, the first resonance region having a sensitivity to radialflow; applying a second static magnetic field from a second NMR tool toa second volume of the formation, the second static magnetic fieldpolarizing a second substantial portion of the formation that is subjectto the second static magnetic field; applying a second oscillatingmagnetic field to a specific part of the second polarized portion toinduce the production of measurable signals, the second oscillatingmagnetic field being applied in accordance with specific field mapsB_(O) and B₁ to produce a second resonance region having a flattenedtorus shape in the second volume, the second resonance region having asensitivity to vertical flow; measuring the induced signals; taking alocal pressure gradient measurement; deriving a horizontal component offlow velocity from the measurable signals induced by the first NMR tool;deriving a vertical component of flow velocity from the measurablesignals induced by the second NMR tool; and deriving a measurement ofpermeability from the horizontal component, the vertical component andthe local pressure gradient measurement.
 53. The method of claim 52,wherein the formation includes a virgin zone that has not been affectedby drilling of the wellbore and a damaged zone that has been affected bydrilling of the wellbore, the shell-shaped resonance region and theflattened torus-shaped resonance regions being located at a radialdistance from an axis of the wellbore, the wellbore having a skin thatcorresponds to pressure drop associated with the damaged zone, themethod further comprising: measuring a radial extent of the damagedzone; measuring permeability of the virgin zone; adjusting the radialdistance of the first and second resonance regions to provide a depthresolved plurality of velocity measurements; determining a permeabilitymeasurement for at least some of the velocity measurements; deriving apermeability measurement for the damaged zone from the determinedpermeability measurements; and determining the skin based on the radialextent of the damaged zone, the permeability of the virgin zone and thepermeability of the damaged zone.
 54. A method of measuring formationpressure of an earth formation utilizing at least one nuclear magneticresonance (NMR) tool placed in a wellbore in the formation, the wellborebeing at a wellbore pressure and having an annular mudcake at a pressurebetween the NMR tool and the formation, the method comprising: measuringthe pressure of the wellbore as a function of time; inducing fluid toflow; applying a static magnetic field from the NMR tool to a volume ofthe formation, the static magnetic field polarizing a substantialportion of the formation that is subject to the static magnetic field;applying an oscillating magnetic field to a specific part of thepolarized portion to induce the production of measurable signals, theoscillating magnetic field being applied in accordance with field mapsB_(O) and B₁ to produce a resonance region having a thin, longcylindrical shell-shape that is sensitive to radial flow; measuring theinduced signals; deriving a horizontal component of flow velocity fromthe measured signals; monitoring the derived flow velocity while varyingwellbore pressure until a zero velocity condition is obtained; andproviding the wellbore pressure when zero velocity occurred as themeasure of formation pressure.
 55. The method of claim 54, whereinformation pressure for a particular zone of the formation is determinedby creating a specific flow path in the particular zone between a pairof first and second packer modules, the NMR tool being located betweenthe first and second packer modules.
 56. The method of claim 55, furthercomprising: utilizing a pressure measurement probe between the first andsecond packer modules to provide a pressure measurement at an interfacebetween the mudcake and the formation; determining transmissivity of themudcake based on the pressure measurement probe measurement, thewellbore pressure measurement and the horizontal component of flowvelocity.
 57. A method of measuring mud filtration rate of a wellbore inan earth formation, the wellbore having a mudcake region, utilizing atleast one nuclear magnetic resonance (NMR) tool placed in the wellborein a substantially steady-state condition, the method comprising:introducing mud into the wellbore at a substantially constant pressure;allowing the mud to diffuse through the mudcake region and into theformation under the influence of the substantially constant pressure;applying a static magnetic field from the NMR tool to a volume of theformation, the static magnetic field polarizing a substantial portion ofthe formation that is subject to the static magnetic field; applying anoscillating magnetic field to a specific part of the polarized portionto induce the production of measurable signals, the oscillating magneticfield being applied in accordance with field maps B_(O) and B₁ toproduce a resonance region having a thin, long cylindrical shell-shapethat is sensitive to radial flow; measuring the induced signals;deriving a horizontal component of flow velocity from the measurablesignals induced by the NMR tool; and integrating the derived flowvelocity over a cylindrical surface concentric with the wellbore toprovide a volumetric flux of the mud filtrate invading the formation.58. Apparatus for measuring flow velocity in a wellbore in an earthformation utilizing nuclear magnetic resonance (NMR) techniques, theapparatus comprising: a first NMR tool that provides a first staticmagnetic field to polarize a first substantial portion of the formationthat is subject to the first static magnetic field, and provides a firstoscillating magnetic field to a specific part of the polarized portionto induce the production of measurable signals, the first oscillatingmagnetic field being provided in accordance with specific field mapsB_(O) and B₁ to produce a first resonance region having a specific shapethat corresponds to a desired sensitivity, the first NMR tool includinga first measurement circuit that measures the induced signals; circuitrythat determines a decay loss factor from the measured induced signals;and circuitry that derives the flow velocity from the determined decayloss factor.
 59. The apparatus of claim 58, wherein the first NMR toolis configured so that the first resonance region is in the shape of athin, long cylindrical shell.
 60. The apparatus of claim 58, wherein thefirst NMR tool is configured so that the first resonance region is aflattened torus-shaped region.
 61. The apparatus of claim 58, whereinthe first NMR tool is configured so that the first resonance region issaddle-point-shaped.
 62. The apparatus of claim 58, wherein the firstmeasurement circuit measures amplitude of the induced signals.
 63. Theapparatus of claim 58, wherein the induced signals are produced fromspin echoes, each spin echo having an echo shape and phase, and thecircuitry that determines decay loss factor analyzes the echo shapes andecho phases in time domain to determine the decay loss factor.
 64. Theapparatus of claim 58, wherein the induced signals are produced fromspin echoes, each spin echo having an echo shape and phase, and thecircuitry that determines decay loss factor analyzes the echo shapes andecho phases in frequency domain to determine the decay loss factor. 65.The apparatus of claim 58, wherein the induced signals are produced fromspin echoes, each spin echo having an echo shape and phase, theapparatus further comprising circuitry that determines flow direction byanalyzing the echo shapes in frequency domain.
 66. The apparatus ofclaim 58, wherein the induced signals are produced from spin echoes,each spin echo having an echo shape and phase, the apparatus furthercomprising circuitry that determines flow direction by analyzing theecho shapes in time domain.
 67. The apparatus of claim 58, wherein thecircuitry that derives flow velocity also distinguishes diffusion frominduced fluid flow.
 68. The apparatus of claim 59, further comprising: asecond NMR tool that provides a second static magnetic field to polarizea second substantial portion of the formation that is subject to thesecond static magnetic field, and provides a second oscillating magneticfield to a second specific part of the polarized portion to induce theproduction of measurable signals in the second specific part, the secondoscillating magnetic field being provided in accordance with specificfield maps B_(O) and B₁ to produce a second resonance region having aspecific shape that corresponds to a desired sensitivity different thanthat of the first NMR tool, the second NMR tool including a secondmeasurement circuit that measures the induced signals in the secondspecific part.
 69. The apparatus of claim 68, wherein the first andsecond NMR tools are included within a drill string and NMR measurementsof flow velocity may be made while drilling of the wellbore occurs. 70.The apparatus of claim 68, wherein the first and second NMR tools areattached to a drill string within the wellbore, the apparatus furthercomprising: first and second packer modules attached to the drillstring, the first NMR tool being located on the drill string between thefirst and second packer modules.
 71. The apparatus of claim 58, whereinthe first NMR tool is attached to a drill string within the wellbore,the apparatus further comprising: first and second packer modulesmounted on the drill string such that the first NMR tool is mountedbetween the first and second packer modules; and a pressure measurementprobe that can measure pressure at an interface between a formation anda mudcake, the pressure measurement probe being mounted on the drillstring between the first and second packer modules.
 72. The apparatus ofclaim 71, wherein the circuitry that derives the flow velocity from thedetermined decay loss factor derives a horizontal component of flowvelocity from the measurable signals induced by the first NMR tool and avertical component of flow velocity from the measurable signals inducedby the second NMR tool, the apparatus further comprising: circuitry thatderives a measurement of permeability from the horizontal component, thevertical component and local gradient pressure measurements from thepressure measurement probe.
 73. The apparatus of claim 58, wherein theNMR tool is included within a drill string and NMR measurements of flowvelocity may be made while drilling of the wellbore occurs.